Predicting Contamination and Clean Fluid Properties From Downhole and Wellsite Gas Chromatograms

ABSTRACT

A method may comprise forming a data matrix, extracting chromatographs of a mud filtrate and a formation fluid, extracting concentration profiles of the mud filtrate and the formation fluid, and decomposing a data set on an information handling machine using a bilinear model. A system may comprise a downhole fluid sampling tool and an information handling tool. The downhole fluid sampling tool may comprise one or more multi-chamber sections, one or more fluid module sections, one or more gas chromatographers, wherein the one or more gas chromatographers are disposed in the one or more fluid module sections, and an information handling system.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.16/449,144, filed Jun. 21, 2019, which is incorporated by reference inits entirety.

BACKGROUND

During oil and gas exploration, many types of information may becollected and analyzed. The information may be used to determine thequantity and quality of hydrocarbons in a reservoir and to develop ormodify strategies for hydrocarbon production. For instance, theinformation may be used for reservoir evaluation, flow assurance,reservoir stimulation, facility enhancement, production enhancementstrategies, and reserve estimation. One technique for collectingrelevant information involves obtaining and analyzing fluid samples froma reservoir of interest. There are a variety of different tools that maybe used to obtain the fluid sample. The fluid sample may then beanalyzed to determine fluid properties, including, without limitation,component concentrations, plus fraction molecular weight, gas-oilratios, bubble point, dew point, phase envelope, viscosity, combinationsthereof, or the like.

Due to overbalance pressure in a wellbore, drilling fluid invades theformation in the vicinity of the wellbore during drilling. Unlikewater-based mud (WBM), oil-based mud (OBM) is miscible with theformation fluid and therefore changes the composition and the propertiesof the original formation fluid. For highly contaminated fluid, themeasured composition and properties are not representative of theoriginal formation fluid. Therefore, accurate composition and pressure,volume, and temperature (PVT) properties may characterize reservoirfluid and understanding architectural complexities of oil reservoirs.Understanding compartmentalization within reservoir and compositionalgrading with a compartment is essential to maximize oil recovery andthese requires knowledge of clean formation fluid composition andproperties are various depth in the reservoir.

Currently, methods and systems for reservoir architectural complexitiesinclude seismic survey and petrophysical logging tools. However,hydraulically sealing barriers may be quite thin and are often invisibleto seismic response and high-resolution petrophysical measurementsprovide limited depth of investigation.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define thedisclosure;

FIG. 1 is a schematic diagram of an example downhole fluid sampling toolon a wireline;

FIG. 2 is a schematic diagram of an example downhole fluid sampling toolon a drill string;

FIG. 3 is a schematic diagram of a downhole fluid sampling tool with afilter disposed in a chamber; and

FIG. 4 illustrates a workflow to analyze mud filtrate and differentsample taken downhole.

DETAILED DESCRIPTION

Downhole sampling is a downhole operation that is used for formationevaluation, asset decisions, and operational decisions. As disclosedbelow, measurement operations of downhole fluid may be performed by aGas Chromatography (GC) analyzer either at wellsite and/or downhole. Itshould be noted that while GC may be referred to within the document, GCincludes all methods of chromatography. For example, liquidchromatography, thin layer chromatography, and/or the like. Includedwithin chromatography is hyphenated chromatography such as any method ofchromatography with mass spectroscopy, thermal conductivity detection,ultraviolet detection, and/or the like. Additionally, chromatography maybe performed separately and augmented with other information that isindependently formed from mass spectroscopy, microfluidic analysis,optical analysis, and/or the like. In some examples, devices providingchromatography like data defined as “differentiated compositional data”(i.e., compositional concentration as a function of molecular weight, orcompositional concentration as a function of molecular size index, orcompositional concentration as a function of vapor pressure) may beutilized. Additionally, the compositional concentration may be describedagainst a functional change in component physical property. Such datamay be generated by methods including but not limited to microfluidicanalysis in combination with mass spectroscopy or membrane separation ormass balance or surface wave acoustic analysis. For wellsite with a GC,samples from different depth in addition to the filtrate sample may beanalyzed together on site. Similarly, for downhole GC, samples atdifferent pumpout volume at the same depth or different depth may beanalyzed together. Analysis of the pumpout may provide mud filtratecontamination level, clean fluid composition, and fluid properties. Theclean fluid composition and properties may be used for continuityassessment or augmentation of fluid data when used in comparison withdownhole samples. Furthermore, reservoir architecture includingparameters such as compositional grading, and compartmentalization maybe determined. The compositional parameters determined may be used inreservoir simulation.

FIG. 1 is a schematic diagram is shown of downhole fluid sampling tool100 on a conveyance 102. As illustrated, wellbore 104 may extend throughsubterranean formation 106. In examples, reservoir fluid may becontaminated with well fluid (e.g., drilling fluid) from wellbore 104.As described herein, the fluid sample may be analyzed to determine fluidcontamination and other fluid properties of the reservoir fluid. Asillustrated, a wellbore 104 may extend through subterranean formation106. While the wellbore 104 is shown extending generally vertically intothe subterranean formation 106, the principles described herein are alsoapplicable to wellbores that extend at an angle through the subterraneanformation 106, such as horizontal and slanted wellbores. For example,although FIG. 1 shows a vertical or low inclination angle well, highinclination angle or horizontal placement of the well and equipment isalso possible. It should further be noted that while FIG. 1 generallydepicts a land-based operation, those skilled in the art will readilyrecognize that the principles described herein are equally applicable tosubsea operations that employ floating or sea-based platforms and rigs,without departing from the scope of the disclosure.

As illustrated, a hoist 108 may be used to run downhole fluid samplingtool 100 into wellbore 104. Hoist 108 may be disposed on a vehicle 110.Hoist 108 may be used, for example, to raise and lower conveyance 102 inwellbore 104. While hoist 108 is shown on vehicle 110, it should beunderstood that conveyance 102 may alternatively be disposed from ahoist 108 that is installed at surface 112 instead of being located onvehicle 110. Downhole fluid sampling tool 100 may be suspended inwellbore 104 on conveyance 102. Other conveyance types may be used forconveying downhole fluid sampling tool 100 into wellbore 104, includingcoiled tubing and wired drill pipe, for example. Downhole fluid samplingtool 100 may include a tool body 114, which may be elongated as shown onFIG. 1 . Tool body 114 may be any suitable material, including withoutlimitation titanium, stainless steel, alloys, plastic, combinationsthereof, and the like. Downhole fluid sampling tool 100 may furtherinclude one or more sensors 116 for measuring properties of the fluidsample, reservoir fluid, wellbore 104, subterranean formation 106, orthe like. In examples, downhole fluid sampling tool 100 may also includea fluid analysis module 118, which may be operable to processinformation regarding fluid sample, as described below. Downhole fluidsampling tool 100 may be used to collect fluid samples from subterraneanformation 106 and may obtain and separately store different fluidsamples from subterranean formation 106.

In examples, fluid analysis module 118 may include at least one a sensorthat may continuously monitor a reservoir fluid. Such sensors includeoptical sensors, acoustic sensors, electromagnetic sensors, conductivitysensors, resistivity sensors, selective electrodes, density sensors,mass sensors, thermal sensors, chromatography sensors, viscositysensors, bubble point sensors, fluid compressibility sensors, flow ratesensors. Sensors may measure a contrast between drilling fluid filtrateproperties and formation fluid properties.

In examples, fluid analysis module 118 may be a gas chromatographyanalyzer (GC). A gas chromatography analyzer may separate and analyzecompounds that may be vaporized without decomposition. Fluid samplesfrom wellbore 104 may be injected into a GC column and vaporized.Different compounds may be separated due to their retention timedifference in the vapor state. Analyses of the compounds may bedisplayed in GC chromatographs. In examples, a mixture of formationfluid and drilling fluid filtrate may be separated and analyzed todetermine the properties within the formation fluid and drilling fluidfiltrate.

Fluid analysis module 118 may be operable to derive properties andcharacterize the fluid sample. By way of example, fluid analysis module118 may measure absorption, transmittance, or reflectance spectra andtranslate such measurements into component concentrations of the fluidsample, which may be lumped component concentrations, as describedabove. The fluid analysis module 118 may also measure gas-to-oil ratio,fluid composition, water cut, live fluid density, live fluid viscosity,formation pressure, and formation temperature. Fluid analysis module 118may also be operable to determine fluid contamination of the fluidsample and may include any instrumentality or aggregate ofinstrumentalities operable to compute, classify, process, transmit,receive, retrieve, originate, switch, store, display, manifest, detect,record, reproduce, handle, or utilize any form of information,intelligence, or data for business, scientific, control, or otherpurposes. For example, fluid analysis module 118 may include randomaccess memory (RAM), one or more processing units, such as a centralprocessing unit (CPU), or hardware or software control logic, ROM,and/or other types of nonvolatile memory.

Any suitable technique may be used for transmitting signals from thedownhole fluid sampling tool 100 to surface 112. As illustrated, acommunication link 120 (which may be wired or wireless, for example) maybe provided that may transmit data from downhole fluid sampling tool 100to an information handling system 122 at surface 112. Informationhandling system 122 may include a processing unit 124, a monitor 126, aninput device 128 (e.g., keyboard, mouse, etc.), and/or computer media130 (e.g., optical disks, magnetic disks) that can store coderepresentative of the methods described herein. Information handlingsystem 122 may act as a data acquisition system and possibly a dataprocessing system that analyzes information from downhole fluid samplingtool 100. For example, information handling system 122 may process theinformation from downhole fluid sampling tool 100 for determination offluid contamination. Information handling system 122 may also determineadditional properties of the fluid sample (or reservoir fluid), such ascomponent concentrations, pressure-volume-temperature properties (e.g.,bubble point, phase envelop prediction, etc.) based on the fluidcharacterization. This processing may occur at surface 112 in real-time.Alternatively, the processing may occur downhole hole or at surface 112or another location after recovery of downhole fluid sampling tool 100from wellbore 104. Alternatively, the processing may be performed by aninformation handling system in wellbore 104, such as fluid analysismodule 118. The resultant fluid contamination and fluid properties maythen be transmitted to surface 112, for example, in real-time.

It should be noted that in examples a gas chromatographer 132 may bedisposed on surface 112 and analyze samples captures by downhole fluidsampling tool 100. For example, fluid analysis module 118 may capturefluid samples and bring them to the surface 112 for analysis at thewellsite. As illustrated, gas chromatographer 132 may be disposed invehicle 110. However, gas chromatographer 132 may be a standaloneassembly that may be available at the wellsite. Additionally,information handling system 122 may be connected to gas chromatographer132 through communication link 120. In examples, gas chromatographer 132may operate and function as described above.

Referring now to FIG. 2 , FIG. 2 is a schematic diagram is shown ofdownhole fluid sampling tool 100 disposed on a drill string 200 in adrilling operation. Downhole fluid sampling tool 100 may be used toobtain a fluid sample, for example, a fluid sample of a reservoir fluidfrom subterranean formation 106. The reservoir fluid may be contaminatedwith well fluid (e.g., drilling fluid) from wellbore 104. As describedherein, the fluid sample may be analyzed to determine fluidcontamination and other fluid properties of the reservoir fluid. Asillustrated, a wellbore 104 may extend through subterranean formation106. While the wellbore 104 is shown extending generally vertically intothe subterranean formation 106, the principles described herein are alsoapplicable to wellbores that extend at an angle through the subterraneanformation 106, such as horizontal and slanted wellbores. For example,although FIG. 2 shows a vertical or low inclination angle well, highinclination angle or horizontal placement of the well and equipment isalso possible. It should further be noted that while FIG. 2 generallydepicts a land-based operation, those skilled in the art will readilyrecognize that the principles described herein are equally applicable tosubsea operations that employ floating or sea-based platforms and rigs,without departing from the scope of the disclosure.

As illustrated, a drilling platform 202 may support a derrick 204 havinga traveling block 206 for raising and lowering drill string 200. Drillstring 200 may include, but is not limited to, drill pipe and coiledtubing, as generally known to those skilled in the art. A kelly 208 maysupport drill string 200 as it may be lowered through a rotary table210. A drill bit 212 may be attached to the distal end of drill string200 and may be driven either by a downhole motor and/or via rotation ofdrill string 200 from the surface 112. Without limitation, drill bit 212may include, roller cone bits, PDC bits, natural diamond bits, any holeopeners, reamers, coring bits, and the like. As drill bit 212 rotates,it may create and extend wellbore 104 that penetrates varioussubterranean formations 106. A pump 214 may circulate drilling fluidthrough a feed pipe 216 to kelly 208, downhole through interior of drillstring 200, through orifices in drill bit 212, back to surface 112 viaannulus 218 surrounding drill string 200, and into a retention pit 220.

Drill bit 212 may be just one piece of a downhole assembly that mayinclude one or more drill collars 222 and downhole fluid sampling tool100. Downhole fluid sampling tool 100, which may be built into the drillcollars 22) may gather measurements and fluid samples as describedherein. One or more of the drill collars 222 may form a tool body 114,which may be elongated as shown on FIG. 2 . Tool body 114 may be anysuitable material, including without limitation titanium, stainlesssteel, alloys, plastic, combinations thereof, and the like. Downholefluid sampling tool 100 may be similar in configuration and operation todownhole fluid sampling tool 100 shown on FIG. 1 except that FIG. 2shows downhole fluid sampling tool 100 disposed on drill string 200.Alternatively, the sampling tool may be lowered into the wellbore afterdrilling operations on a wireline.

Downhole fluid sampling tool 100 may further include one or more sensors116 for measuring properties of the fluid sample reservoir fluid,wellbore 104, subterranean formation 106, or the like. The properties ofthe fluid are measured as the fluid passes from the formation throughthe tool and into either the wellbore or a sample container. As fluid isflushed in the near wellbore region by the mechanical pump, the fluidthat passes through the tool generally reduces in drilling fluidfiltrate content, and generally increases in formation fluid content.The downhole fluid sampling tool 100 may be used to collect a fluidsample from subterranean formation 106 when the filtrate content hasbeen determined to be sufficiently low. Sufficiently low depends on thepurpose of sampling. For some laboratory testing below 10% drillingfluid contamination is sufficiently low, and for other testing below 1%drilling fluid filtrate contamination is sufficiently low. Sufficientlylow also depends on the nature of the formation fluid such that lowerrequirements are generally needed, the lighter the oil as designatedwith either a higher GOR or a higher API gravity. Sufficiently low alsodepends on the rate of cleanup in a cost benefit analysis since longerpumpout times required to incrementally reduce the contamination levelsmay have prohibitively large costs. As previously described, the fluidsample may include a reservoir fluid, which may be contaminated with adrilling fluid or drilling fluid filtrate. Downhole fluid sampling tool100 may obtain and separately store different fluid samples fromsubterranean formation 106 with fluid analysis module 118. Fluidanalysis module 118 may operate and function in the same manner asdescribed above. However, storing of the fluid samples in the downholefluid sampling tool 100 may be based on the determination of the fluidcontamination. For example, if the fluid contamination exceeds atolerance, then the fluid sample may not be stored. If the fluidcontamination is within a tolerance, then the fluid sample may be storedin the downhole fluid sampling tool 100.

As previously described, information from downhole fluid sampling tool100 may be transmitted to an information handling system 122, which maybe located at surface 112. As illustrated, communication link 120 (whichmay be wired or wireless, for example) may be provided that may transmitdata from downhole fluid sampling tool 100 to an information handlingsystem 111 at surface 112. Information handling system 140 may include aprocessing unit 124, a monitor 126, an input device 128 (e.g., keyboard,mouse, etc.), and/or computer media 130 (e.g., optical disks, magneticdisks) that may store code representative of the methods describedherein. In addition to, or in place of processing at surface 112,processing may occur downhole (e.g., fluid analysis module 118). Inexamples, information handling system 122 may perform computations toestimate clean fluid composition.

As previously described above, a gas chromatographer 132 may be disposedon surface 112 and analyze samples captures by downhole fluid samplingtool 100. For example, fluid analysis module 118 may capture fluidsamples and bring them to the surface 112 for analysis at the wellsite.As illustrated, gas chromatographer 132 may be a standalone assemblythat may be available at the wellsite. Additionally, informationhandling system 122 may be connected to gas chromatographer 132 throughcommunication link 120. In examples, gas chromatographer 132 may operateand function as described above.

FIG. 3 is a schematic of downhole fluid sampling tool 100. In examples,downhole fluid sampling tool 100 includes a power telemetry section 302through which the tool communicates with other actuators and sensors 116in drill string 200 or conveyance 102 (e.g., referring to FIGS. 1 and 2), and/or directly with a surface telemetry system (not illustrated). Inexamples, power telemetry section 302 may also be a port through whichthe various actuators (e.g. valves) and sensors (e.g., temperature andpressure sensors) in the downhole fluid sampling tool 100 may becontrolled and monitored. In examples, power telemetry section 302includes a computer that exercises the control and monitoring function.In one embodiment, the control and monitoring function is performed by acomputer in another part of the drill string or wireline tool (notshown) or by information handling system 122 on surface 112 (e.g.,referring to FIGS. 1 and 2 ).

In examples, downhole fluid sampling tool 100 includes a dual probesection 304, which extracts fluid from the reservoir and delivers it toa channel 306 that extends from one end of downhole fluid sampling tool100 to the other. Without limitation, dual probe section 304 includestwo probes 318, 320 which may extend from downhole fluid sampling tool100 and press against the inner wall of wellbore 104 (e.g., referring toFIG. 1 ). Probe channels 322, 324 may connect probes 318, 320 to channel306. The high-volume bidirectional pump 312 may be used to pump fluidsfrom the reservoir, through probe channels 322, 324 and to channel 306.Alternatively, a low volume pump 326 may be used for this purpose. Twostandoffs or stabilizers 328, 330 hold downhole fluid sampling tool 100in place as probes 318, 320 press against the wall of wellbore 104. Inexamples, probes 318, 320 and stabilizers 328, 330 may be retracted whendownhole fluid sampling tool 100 may be in motion and probes 318, 320and stabilizers 328, 330 may be extended to sample the formation fluidsat any suitable location in wellbore 104. Other probe sections includefocused sampling probes, oval probes, or packers.

In examples, channel 306 may be connected to other tools disposed ondrill string 200 or conveyance 102 (e.g., referring to FIGS. 1 and 2 ).In examples, downhole fluid sampling tool 100 may also include a quartzgauge section 308, which may include sensors to allow measurement ofproperties, such as temperature and pressure, of fluid in channel 306.Additionally, downhole fluid sampling tool 100 may include aflow-control pump-out section 310, which may include a high-volumebidirectional pump 312 for pumping fluid through channel 306. Inexamples, downhole fluid sampling tool 100 may include two multi-chambersections 314, 316, referred to collectively as multi-chamber sections314, 316 or individually as first multi-chamber section 314 and secondmulti-chamber section 316, respectively.

In examples, multi-chamber sections 314, 316 may be separated fromflow-control pump-out section 310 by fluid analysis module 118, whichmay house at least one sensor, for example gas chromatographer 132. Gaschromatographer 132 may be displaced within fluid analysis module 118in-line with channel 306 to be a “flow through” sensor. In alternateexamples, gas chromatographer 132 may be connected to channel 306 via anoffshoot of channel 306. Without limitation, fluid analysis module 118may also include optical sensors, acoustic sensors, electromagneticsensors, conductivity sensors, resistivity sensors, selectiveelectrodes, density sensors, mass sensors, thermal sensors,chromatography sensors, viscosity sensors, bubble point sensors, fluidcompressibility sensors, flow rate sensors, microfluidic sensors,selective electrodes such as ion selective electrodes, and/orcombinations thereof. In examples, gas chromatographer 132 may operateand/or function as described above.

Additionally, multi-chamber section 314, 316 may include access channel336 and chamber access channel 338. Without limitation, access channel336 and chamber access channel 338 may operate and function to eitherallow a solids-containing fluid (e.g., mud) disposed in wellbore 104 inor provide a path for removing fluid from downhole fluid sampling tool100 into wellbore 104. As illustrated, multi-chamber section 314, 316may include a plurality of chambers 340. Chambers 340 may be samplingchamber that may be used to sample wellbore fluids, formation fluids,and/or the like during measurement operations.

As discussed above, gas chromatographer 132 may use methods of gaschromatography (GC) at a wellsite or downhole to analyze mud filtrateand different samples. At the wellsite, in addition to analyzing the mudfiltrate sample, samples at different depth may be analyzed using GC.Assumption that the formation fluid at different depth may be similarand that mud filtrate each of the depths may be similar is made.Chromatograms of mud filtrates and that of samples at different depthcombined together as data matrix and the contamination is treated as amixing problem of formation fluid and mud filtrate. Methods such asmultivariate curve resolution (MCR) may be used to estimate theconcentrate and spectra of formation fluid and mud filtrate. Theconcentration of the mud filtrate gives the contamination level of eachsample and clean fluid composition may be estimated from the spectradata of formation fluid. Described herein, MCR is an endmemberdeconvolution technique, and use of the MCR will refer to any endmemberdeconvolution technique. Other endmember deconvolution techniques thatMCR will refer to include but are not limited to factor analysis,wavelet analysis, principal component analysis, and other linear ornonlinear pattern recognition techniques.

Similarly, for downhole GC, multiple samples during pumpout at the samedepth are analyzed using GC. It is assumed that mud filtrate atdifferent pumping volume may be the same and fluid composition may alsobe the same. The chromatogram at different pumpout volume at combined toform the data matrix and the problem is treated as a mixing problem offormation fluid and mud filtrate. The concentration of the mud filtrategives the contamination level of each sample and clean fluid compositionmay be estimated from the spectra data of the formation fluid.

FIG. 4 illustrates workflow 400 to analyze mud filtrate and differentsample taken downhole. Workflow 400 may begin with step 402 to form adata matrix. The data matrix may include the chromatograms from mudfiltrate and from different samples where from different depth, samplesobtained when downhole fluid sampling tool 100 (e.g., referring to FIG.1 ) is brought to the surface or from the sample depth taking atdifferent pumping volume during the pumpout for downhole GC application.Samples taken downhole may include two components (mud filtrate andformation fluid) coexisting in each chromatogram. In step 404 one ormore chromatographs may be formed from an extracted spectra of mudfiltrate and formation fluid. This step may include using a MultivariateCurve Resolution (MCR) to extract the pure spectra of each of thecomponents coexisting in the samples. An MCR is a method for resolvingmixtures by determining the number of constituents, their responseprofiles and their estimated concentrations, when no prior informationis available about the nature and composition of these mixtures. In step406 an operator may extract a concentration profile of the mud filtrateand formation fluid. This step may include using an MCR to extract theconcentration profiles of each component. In step 408 an operator mayuse an information handling machine 122 (e.g., referring to FIG. 1 ) todecompose data according to a bilinear model, D=CS^(T)+E, Where D—Datamatrix, C—resolved concentration profiles, S—resolved spectra profiles,T is the transpose of matrix S, and E—is the error in the estimation.

Using workflow 400 may improve estimation of the clean fluidcompositions: methane (C1), ethane (C2), propane (C3), butane (C4) andpentane (C5) hexane C6 and heptane plus (C7+) using GC data and MCRmethod. As discussed above improvements may allow for using clean fluidcomposition and equation of state to estimate physical and/ or chemicalproperties including fluid density, bubble point and gas to oil ratio(GOR) at downhole condition in real time. Improvements from workflow 400may also allow for the use of clean fluid chemical and/or physicalproperties from GC data/ MCR data to guide subsequent wireline or LWDsampling or pressure testing operations. Additional improvements may useclean fluid compositions at different depths to determinecompartmentalization and compositional gradient within a compartment.

Compartmentalization is defined as identifying and producing differenthydrocarbon deposits within a subterranean environment. In examples,there may be a single hydrocarbon deposit or multiple hydrocarbondeposits within a compartment. A compartment is defined as a geographicarea over which hydrocarbons may be obtained. For example, two separatecompartments may be produced hydrocarbons separately as the subterraneanenvironment may not allow for fluid flow between each compartment.However, in some subterranean environments different hydrocarbondeposits may be fluidly connected. Therefore, if one deposit is drainedthan the second deposit with drain as well. Both deposits would begrouped into a single compartment because as one deposit is drainedfluid, fluid within both deposits will drain.

Fluid within each compartment, each deposit, may have variations. Fluidvariations may be monitored and graded as a compositional gradient as afunction of depth. Compositional grading may be found using equation ofstate models. To determine compositional grading, properties offormation fluid are found, as discussed above, by determining the amountof fluid filtrate within the formation fluid. After determiningproperties of the formation fluid, an MCR algorithm may use theproperties with an equation of state to determine compositional grade.Other methods may be utilized to determine compositional grade, such asexponential models for growth or decline may be used.

When determining compositional grading, if a model such as an equationof state model, physical model, or an empirical model does not fitcharacteristics of the hydrocarbon deposit, it may be assumed that thehydrocarbon deposit may include two or more separate compartments. Fluiddynamics may be used to determine different hydrocarbon deposits. Forexample, a higher density fluid will not be disposed on a lower densityfluid and a lower GOR fluid will not be on a higher GOR fluid. Fluiddynamics may indicate separate hydrocarbon deposits without using atrend model.

Equation of state model, discussed above, may generally be physicalmodels that may be cubic equation of state models. Examples of cubicequation of state models may be a Peng-Robinson, SRK, and/or the like.Additionally, equation state models may be non-cubic equation of statemodels such as, PC-SAFT, polymer equation of state, and/or the like.Each equation of state model may be used to measure at least a portionof the fluid such as asphaltene variation. Equation of state models mayutilize physics in understanding reservoir characteristics such astemperature, pressure, and composition. While empirical models are goodat testing for continuity, they may fit to discontinuous fluid systems,which may provide false positives.

The preceding description provides various embodiments of systems andmethods of use which may contain different method steps and alternativecombinations of components. It should be understood that, althoughindividual embodiments may be discussed herein, the present disclosurecovers all combinations of the disclosed embodiments, including, withoutlimitation, the different component combinations, method stepcombinations, and properties of the system.

Statement 1. A method may comprise forming a data matrix; extractingchromatographs of a mud filtrate and a formation fluid; extractingconcentration profiles of the mud filtrate and the formation fluid; anddecomposing a data set on an information handling machine using abilinear model.

Statement 2. The method of statement 1, wherein the bilinear model isD=CS^(T)+E, wherein D is the data matrix, C is the concentrationprofiles of the mud filtrate and the formation fluid, S ischromatographs of the mud filtrate and the formation fluid, T is atranspose of matrix S, and E is error.

Statement 3. The method of statement 1 or 2, further comprising usingmultivariate curve resolution for the extracting chromatographs of themud filtrate and the formation fluid.

Statement 4. The method of statements 1-3, further comprising using amultivariate curve resolution for extracting a concentration profile ofthe mud filtrate and the formation fluid.

Statement 5. The method of statements 1-4, wherein the data matrixcomprises of one or more chromatograms from the mud filtrate or theformation fluid.

Statement 6. The method of statements 1-5, further comprising performingthe extracting chromatographs and the extracting concentration profilesat a well site or in a downhole fluid sampling tool.

Statement 7. A method may comprise disposing a downhole fluid samplingtool into a wellbore at a first location, wherein the downhole fluidsampling tool comprises: at least one multi-chamber section; at leastone fluid module section; and activating a pump to draw asolids-containing fluid disposed in the wellbore into the downhole fluidsampling tool; raising the downhole fluid sampling tool to surface;disposing the solids-containing fluid into a gas chromatographer;measuring the drilling fluid filtrate from the solids-containing fluidwith the gas chromatographer to form data; inputting the data into aninformation handling system; forming a data matrix from the data;extracting chromatographs of a mud filtrate and formation fluid from thesolids-containing fluid; extracting a concentration profile of the mudfiltrate and the formation fluid; and decomposing a data set on aninformation handling machine using a bilinear model.

Statement 8. The method of statement 7, wherein the bilinear model isD=CS^(T)+E, wherein D is the data matrix, C is the concentration profileof the mud filtrate and the formation fluid, S is the chromatographs ofthe mud filtrate and the formation fluid, T is a transpose of matrix S,and E is error.

Statement 9. The method of statements 7 or 8, further comprising usingmultivariate curve resolution for the extracting a spectra or aconcentration profile of a mud filtrate and formation fluid.

Statement 10. The method of statements 7-9, wherein the data matrixcomprises of one or more chromatograms from the mud filtrate or theformation fluid.

Statement 11. The method of statements 7-10, further comprisingperforming the extracting chromatographs and the extractingconcentration profiles in the downhole fluid sampling tool.

Statement 12. A system may comprise a downhole fluid sampling toolcomprising: one or more multi-chamber sections; one or more fluid modulesections; one or more gas chromatographers, wherein the one or more gaschromatographers are disposed in the one or more fluid module sections;and an information handling system configured to: form a data matrix;extract chromatographs of a mud filtrate and a formation fluid from thedownhole fluid sampling tool; extract a concentration profile of the mudfiltrate and the formation fluid from the downhole fluid sampling tool;and decompose a data set with , D=CS^(T)+E, wherein D is the datamatrix, C is the concentration profile of the mud filtrate and theformation fluid, S is the chromatographs of the mud filtrate and theformation fluid, T is a transpose of matrix S, and E is error.

Statement 13. The system of statement 12, wherein the informationhandling system is further configured to use multivariate curveresolution for the extracting chromatograph profiles of a mud filtrateand the formation fluid.

Statement 14. The system of statements 12 or 13, wherein the informationhandling system is further configured to use multivariate curveresolution for extracting a concentration profile of the mud filtrateand the formation fluid.

Statement 15. The system of statements 12-14, wherein the data matrixcomprises of one or more chromatograms from the mud filtrate or theformation fluid.

Statement 16. The system of statements 12-15, wherein the downhole fluidsampling tool further comprises one or more probes.

Statement 17. The system of statements 12-16, wherein the downhole fluidsampling tool further comprises one or more stabilizers.

Statement 18. The system of statements 12-17, wherein the downhole fluidsampling tool is connected to a conveyance.

Statement 19. The system of statements 12-18, wherein the downhole fluidsampling tool is connected to a drill string.

Statement 20. The system of statements 12-19, wherein the downhole fluidsampling tool further comprises a pump, wherein the pump is configuredto draw a solids-containing fluid into the one or more fluid modulesections.

It should be understood that the compositions and methods are describedin terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the disclosure covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.It is therefore evident that the particular illustrative embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the present disclosure. Ifthere is any conflict in the usages of a word or term in thisspecification and one or more patent(s) or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

What is claimed is:
 1. A method comprising: collecting at least a firstsample and a second sample from a downhole fluid with a downhole fluidsampling tool; measuring the first sample and the second sample with asensor to form a first measured sample and a second measured sample;forming a data matrix, wherein the data matrix comprises the firstmeasured sample and the second measured sample; extracting the firstmeasured sample and the second measured sample, wherein the firstmeasured sample is from a mud filtrate and the second measured sample isfrom a formation fluid; extracting concentration profiles of the mudfiltrate and the formation fluid; and decomposing a data set on aninformation handling machine using a model.
 2. The method of claim 1,wherein the model is D=CS^(T)+E, wherein D is the data matrix, C is theconcentration profiles of the mud filtrate and the formation fluid, S isthe first measured sample and the second measured sample, T is atranspose of matrix S, and E is error.
 3. The method of claim 1, furthercomprising using multivariate curve resolution for the extracting thefirst measured sample and the second measured sample or the extractingthe concentration profile of the mud filtrate and the formation fluid.4. The method of claim 1, further comprising compartmentalizing aformation into one or more compartments based at least in part on theconcentration profiles and identifying a compositional gradient for eachof the one or more compartments.
 5. The method of claim 1, furthercomprising guiding a sampling operation or a pressure testing operationbased at least in part on the concentration profiles.
 6. The method ofclaim 1, further comprising performing the extracting the first measuredsample and the second measured sample and the extracting concentrationprofiles at a well site or in a downhole fluid sampling tool.
 7. Amethod comprising: disposing a downhole fluid sampling tool into awellbore at a first location, wherein the downhole fluid sampling toolcomprises: at least one multi-chamber section; at least one fluid modulesection; and activating a pump to draw a solids-containing fluiddisposed in the wellbore into the downhole fluid sampling tool; raisingthe downhole fluid sampling tool to surface; disposing thesolids-containing fluid into a fluid analysis module; measuring thedrilling fluid filtrate from the solids-containing fluid with a sensordisposed in the fluid analysis module to form data, wherein the datacomprises sensor measurements from each of two or more samples, whereinthe two or more samples comprise a mud filtrate and a formation fluid;inputting the data into an information handling system; forming a datamatrix from the data; extracting one or more measurements of the mudfiltrate and the formation fluid from the solids-containing fluid;extracting a concentration profile of the mud filtrate and the formationfluid; and decomposing a data set on an information handling machineusing a model.
 8. The method of claim 7, wherein the model isD=CS^(T)+E, wherein D is the data matrix, C is the concentration profileof the mud filtrate and the formation fluid, S is the one or moremeasurement of the mud filtrate and the formation fluid, T is atranspose of matrix S, and E is error.
 9. The method of claim 7, furthercomprising using multivariate curve resolution for the extracting aspectra or a concentration profile of a mud filtrate and formationfluid.
 10. The method of claim 7, further comprising performing theextracting one or more measurement and the extracting concentrationprofiles in the downhole fluid sampling tool.
 11. The method of claim 7,wherein the downhole fluid sampling tool further comprises one or moreprobes, one or more stabilizers and is connected to a conveyance ordrill string.
 12. A system comprising: a downhole fluid sampling toolcomprising: one or more multi-chamber sections; one or more fluid modulesections; one or more sensors, wherein the one or more sensors aredisposed in the one or more fluid module sections; and an informationhandling system configured to: form a data matrix; extract one or moremeasurements of a mud filtrate and a formation fluid from the downholefluid sampling tool; extract a concentration profile of the mud filtrateand the formation fluid from the downhole fluid sampling tool; anddecompose a data set with, D=CS^(T)+E, wherein D is the data matrix, Cis the concentration profile of the mud filtrate and the formationfluid, S is the one or more measurements of the mud filtrate and theformation fluid, T is a transpose of matrix S, and E is error.
 13. Thesystem of claim 12, wherein the information handling system is furtherconfigured to use multivariate curve resolution for the extractingchromatograph profiles of a mud filtrate and the formation fluid. 14.The system of claim 12, wherein the information handling system isfurther configured to use multivariate curve resolution for extracting aconcentration profile of the mud filtrate and the formation fluid. 15.The system of claim 12, wherein the data matrix comprises of one or moremeasurements from the mud filtrate or the formation fluid.
 16. Thesystem of claim 12, wherein the downhole fluid sampling tool furthercomprises one or more probes.
 17. The system of claim 12, wherein thedownhole fluid sampling tool further comprises one or more stabilizers.18. The system of claim 12, wherein the downhole fluid sampling tool isconnected to a conveyance.
 19. The system of claim 12, wherein thedownhole fluid sampling tool is connected to a drill string.
 20. Thesystem of claim 12, wherein the downhole fluid sampling tool furthercomprises a pump, wherein the pump is configured to draw asolids-containing fluid into the one or more fluid module sections.